Downhole ranging from multiple boreholes

ABSTRACT

Downhole ranging from multiple wellbores. In one example, multiple transmitters and multiple receivers are disposed in multiple wellbores to exchange electromagnetic signals. By implementing a full compensation technique, a computer system determines multiple compensated signals. A compensated signal is determined from a signal received from a first wellbore and a second signal received from a second wellbore. In another example, a first transmitter is disposed in a first wellbore, a first receiver is disposed in a second wellbore, and either a second transmitter or a second receiver is disposed in either the first wellbore or the second wellbore. By implementing partial compensation techniques, a computer system determines compensated signals. Using the compensated signals, the computer system determines a position of a first wellbore relative to a second wellbore, and provides the position.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional application of U.S. patent applicationSer. No. 14/759,519, filed by Burkay Donderici on Jul. 7, 2015, entitled“DOWNHOLE RANGING FROM MULTIPLE BOREHOLES,” which is a U.S. NationalStage of International Application No. PCT/US2013/030291, filed on Mar.11, 2013, wherein the above-listed applications are commonly assignedwith the present application and are incorporated herein by reference intheir entirety.

TECHNICAL FIELD

The present disclosure relates to software, computer systems, andcomputer-implemented media used in forming wellbores in subsurfaceformations containing hydrocarbons.

BACKGROUND

Wellbores formed in subterranean hydrocarbon reservoirs enable recoveryof a portion of the hydrocarbons using production techniques. Thehydrocarbons can adhere to the reservoirs, for example, due to acombination of capillary forces, adhesive forces, cohesive forces, andhydraulic forces. Steam-assisted gravity drainage (SAGD) is an exampleof an enhanced hydrocarbon recovery technique in which heated treatmentfluids (for example, steam) can be applied to the formation tofacilitate and enhance recovery of the hydrocarbons that are adhered tothe formation. In an implementation of the SAGD technique, an injectionwellbore can be formed adjacent to a production wellbore, and the heatedtreatment fluids can be injected through the injection wellbore into theformation surrounding the production wellbore. The heated fluids candecrease an adherence of the hydrocarbons to the formation, therebyreleasing the hydrocarbons into the production wellbore.

While forming (for example, drilling) the injection wellbore, knowledgeof a location of the production wellbore relative to the injectionwellbore can be important. Ranging is an example of a method to controla position of a wellbore being drilled relative to an existing wellbore.In ranging, an electromagnetic source located in the existing wellboreprovides electromagnetic signals received by sensors in the wellborebeing drilled. In another example of ranging, both the electromagneticsource and the sensors can be located in the wellbore being drilled.Several conditions, for example, wellbore drilling conditions, canadversely affect an ability of the electromagnetic source or the sensors(or both) to exchange the electromagnetic signals, and, consequently,affect ranging in the wellbores.

SUMMARY

In one aspect, a system for ranging in wellbores is disclosed. In oneembodiment, the system includes: a first transmitter disposed in a firstwellbore to transmit electromagnetic signals; a first receiver disposedin a second wellbore to receive the electromagnetic signals transmittedby the first transmitter; either a second transmitter or a secondreceiver disposed in either the first wellbore or the second wellbore tocommunicate electromagnetic signals with the first transmitter or thefirst receiver; and a processor connected to the first transmitter, thefirst receiver, and either the second transmitter or the secondreceiver. The processor is configured to: receive a plurality of signalscommunicated by the first transmitter, the first receiver, and eitherthe second transmitter or the second receiver, wherein the plurality ofsignals includes a signal that corresponds to an electromagnetic signalreceived by the first receiver from the first transmitter; implementcompensation techniques on the plurality of signals resulting in aplurality of compensated signals; process the plurality of compensatedsignals to determine a position of a first wellbore of the plurality ofwellbores relative to a second wellbore of the plurality of wellbores;and provide the position of the first wellbore relative to the secondwellbore.

In another aspect, a computer-readable medium storing instructionsexecutable by a processor to perform operations for ranging in wellboresis disclosed. In one embodiment, the operations include: receiving aplurality of signals communicated between a first transmitter disposedin a first wellbore to transmit electromagnetic signals, a firstreceiver disposed in a second wellbore to receive the electromagneticsignals transmitted by the first transmitter, and either a secondtransmitter or a second receiver disposed in either the first wellboreor the second wellbore to communicate electromagnetic signals with thefirst transmitter or the first receiver, wherein the plurality ofsignals includes a signal that corresponds to an electromagnetic signalreceived by the first receiver from the first transmitter; implementingcompensation techniques on the plurality of signals resulting in acompensated plurality of signals; processing the compensated pluralityof signals to determine a position of a first wellbore of the pluralityof wellbores relative to a second wellbore of the plurality ofwellbores; and providing the position of the first wellbore relative tothe second wellbore.

In yet another aspect, a method for ranging in wellbores is disclosed.In one embodiment, the method includes: receiving, by a processor, aplurality of signals communicated between a first transmitter disposedin a first wellbore to transmit electromagnetic signals, a firstreceiver disposed in a second wellbore to receive the electromagneticsignals transmitted by the first transmitter, and either a secondtransmitter or a second receiver disposed in either the first wellboreor the second wellbore to communicate electromagnetic signals with thefirst transmitter and the first receiver, wherein the plurality ofsignals includes a signal that corresponds to an electromagnetic signalreceived by the first receiver from the first transmitter; implementing,by the processor, compensation techniques on the plurality of signalsresulting in a compensated plurality of signals; processing, by theprocessor, the compensated plurality of signals to determine a positionof a first wellbore of the plurality of wellbores relative to a secondwellbore of the plurality of wellbores; and providing, by the processor,the position of the first wellbore relative to the second wellbore.

DESCRIPTION OF DRAWINGS

FIGS. 1A-1D are schematic, elevation views illustrating examples ofmultiple wellbores for ranging.

FIG. 2 is a block diagram of an example of a system for ranging inmultiple wellbores.

FIG. 3 is an example operational chart that shows relationships betweenprocessing, compensation, and inversion units.

FIGS. 4A and 4B are plots comparing compensated and uncompensatedelectromagnetic signals.

FIG. 5 is a flowchart of an example process for ranging from multiplewellbores implementing full compensation.

FIG. 6 is a flowchart of an example process for ranging from multiplewellbores implementing partial compensation.

Like reference symbols in the various drawings indicate like elements.

DETAILED DESCRIPTION

This disclosure relates to computer-implemented methods, computersystems, and computer-readable media for downhole ranging from multiplewellbores using compensated electromagnetic measurements. In the exampleof a SAGD application, precise ranging of the steam injection wellborecan be important. If the injection wellbore intersects the productionwellbore, a blowout can result from the pressure difference between thewells. If the steam injection wellbore is too far from the productionwellbore, the steam injection may not result in significant increasedrecovery. The ranging process described here can be used to determinethe distance and precise location while drilling the injection wellbore.

Ranging focuses on changes in the positions of electromagnetictransmitters and receivers to provide precise measurements. Thetransmitters and receivers are disposed in wellbores for ranging. Forexample, the transmitters can be placed in a production wellbore andreceivers in a wellbore that is being drilled (for example, for steaminjection). The strength of the transmitters and receivers may notprecisely be known. There can be a degree of variability associated withdifferences in manufacturing, differences in electronics, temperaturechanges, or combinations of them. In addition, an electromagnetic signalmay experience changes, for example, in an approaching target well.Compensation is a technique that can be used to eliminate or minimizesuch effects that can adversely affect measurement of theelectromagnetic signals. For example, compensation can eliminate orminimize the effects of elements (for example, manufacturingdifferences, electronic differences, temperature changes, and the like)to ensure that the remaining changes observed and measured are relevantto the ranging application.

As described below, one or both of two types of compensation—namely,partial compensation and full compensation—can be applied to rangingfrom multiple wellbores used, for example, in enhanced hydrocarbonrecovery. In full compensation implementations, for example, multipleelectromagnetic signal transmitters and multiple electromagneticreceivers can be located in a production wellbore and an injectionwellbore, respectively. In partial compensation implementations, forexample, one electromagnetic signal transmitter and two electromagneticsensors or two electromagnetic signal transmitters and oneelectromagnetic sensor can be located in a production wellbore and aninjection wellbore, respectively. The production wellbore can be anexisting wellbore; the injection wellbore can be one that is beingdrilled adjacent the production wellbore for steam injection. A computersystem described below can implement either or both compensationtechniques when interpreting changes in electromagnetic signals betweenthe one or more transmitters and the one or more receivers to eliminateor minimize some or all of the adverse effects described above. Forexample, by implementing the partial or full compensation technique, thecomputer system can eliminate or minimize confounding effects of anytype of amplitude or phase shift that can be attributable to electronicdrift, drift as a result of temperature change, or unknown phase oramplitude. After the computer system implements the partial or fullcompensation technique (or both), the computer system can use changesobserved in the electromagnetic signal as the basis for measurements foruse in ranging the injection wellbore.

Implementing partial or full compensation techniques (or both) on theelectromagnetic signals prior to ranging can decrease a reliance onother correction or calibration techniques that are either complicatedor impose strict requirements on electronics. Relative to the othercorrection/calibration techniques, the compensation technique can easerequirements on electronics and result in simpler and more robustmeasurements. The compensation techniques described below can provideextended coverage in the area of ranging. The measurements can be moreaccurate and robust than conventional compensation techniques. Thecompensation techniques can also provide more design flexibility inelectronics or mechanics (or both) implemented in enhanced hydrocarbonrecovery techniques, such as SAGD. The compensation can correct for theeffect of temperature, fatigue or corrosion on sensor electronics suchas amplitude or phase drifts. The compensation can also allow easierdeployment of sensors since no in-situ calibration is required.

FIGS. 1A and 1B are schematic, elevation views illustrating examples ofmultiple wellbores for ranging implementing full compensation. In someimplementations, multiple transmitters (for example, a first transmitter102, a second transmitter 104) can be disposed in multiple wellbores(for example, a first wellbore 110, a second wellbore 122). Eachtransmitter (i.e., the first transmitter 102, the second transmitter104) can transmit electromagnetic signals. Multiple receivers (forexample, a first receiver 114, a second receiver 116) can be disposed inthe multiple wellbores. Each receiver (i.e., the first receiver 114, thesecond receiver 116) can receive electromagnetic signals transmitted bythe multiple transmitters. For example, the first transmitter 102 andthe second transmitter 104 can be disposed in a pre-existing productionwellbore 110, and can be spaced apart by a distance ranging between 2feet and 50 feet. The first receiver 114 and the second receiver 116 canbe disposed in a SAGD wellbore 122 being drilled, and can be spacedapart by a distance ranging between 2 feet and 50 feet. In sum, at leasttwo transmitters and at least two receivers can be disposed in at leasttwo wellbores to implement full compensation.

In some implementations, the first receiver 114 and the second receiver116 can be affixed to a Measuring While Drilling (MWD) tool 126 disposedin the SAGD wellbore 122. Alternatively, or in addition, the sensors canbe affixed to a production logging tool, outside the casings on specialhousings, inside the casing to transmit or receive from the formation,in open-hole sections in the wells, or in combinations of them. Thesensors can alternatively or in addition be placed on a production toolinside the casing. A casing can be all or portions of one or more casingstrings disposed in the wellbore.

FIGS. 1C and 1D are schematic, elevation views illustrating examples ofmultiple wellbores for ranging implementing partial compensation. Insome implementations, a first transmitter 152 can be disposed in a firstwellbore 154 (for example, a pre-existing production wellbore) totransmit electromagnetic signals. A first receiver 156 can be disposedin a second wellbore 160 (for example, a SAGD wellbore) to receive theelectromagnetic signals transmitted by the first transmitter. Either asecond transmitter or a second receiver can be disposed in either thefirst wellbore or the second wellbore to exchange electromagneticsignals with the first transmitter and the first receiver. For example,as shown in FIG. 1C, the first receiver 156 and a second receiver 158can be disposed on a MWD tool 162 in the second wellbore 160. In anotherexample, as shown in FIG. 1D, a first transmitter 172 and a secondtransmitter 179 can be disposed in a pre-existing production wellbore176 to exchange electromagnetic signals with a receiver 178 disposed ona production logging tool 182 disposed in a SAGD wellbore 180. In sum,at least a first transmitter, at least a first receiver, and either asecond transmitter or a second receiver can be disposed in at least twowellbores to implement partial compensation.

The configuration of the first wellbore relative to the second wellbore(for example, the arrangement of the wellbore 110 relative to thewellbore 122, the arrangement of the wellbore 112 relative to thewellbore 124, the arrangement of the wellbore 154 relative to thewellbore 160, or the arrangement of the wellbore 176 relative to thewellbore 180), and the arrangement of transmitters and receivers in thefirst wellbore and the second wellbore are exemplary. Several otherconfigurations are possible. For example, in both partial and fullcompensation implementations, more than two transmitters and more thantwo receivers can be disposed in the second wellbore 122 and the firstwellbore 110, respectively. In this case, compensation may be performedin fours. A transmitter and a receiver can be disposed in the samewellbore in both partial and full compensation implementations. Thefirst wellbore is substantially perpendicular to the second wellbore,for example, in the formation 140 (FIG. 1A) or in the formation 166(FIG. 1C). Alternatively, as shown in the formation 150 (FIG. 1B) or inthe formation 189 (FIG. 1D), a third wellbore can be substantiallyparallel to a fourth wellbore.

One of the two wellbores can be a production wellbore in which one ormore transmitters are disposed. The other wellbore can be an injectionwellbore in which a tool (for example, a MWD tool 128) is disposed. In afull compensation implementation, multiple receivers (for example, athird receiver 118 and a fourth receiver 120) can be disposed in thefourth wellbore 124, for example, affixed to the MWD tool 128. In apartial compensation implementation, one transmitter 178 can be affixedto a tool (for example, the production logging tool 182) in the wellbore180. In some implementations, the wellbores formed in the formation canbe at any angle to each other instead of being either substantiallyparallel or substantially perpendicular. Transmitters and receivers canbe interchangeably disposed in any wellbore. In sum, the techniquesdescribed here can be implemented in ranging wellbores of anyconfiguration by disposing the sensors (i.e., the transmitters and thereceivers) in any of the two wellbores.

In some full compensation implementations, the first transmitter 102,the first receiver 114 and the second receiver 116 can be disposed inthe first wellbore 110 and the second wellbore 122 (FIG. 1A) such thatan angle formed by a first line connecting the first receiver 114 andthe first transmitter 102 and a second line connecting the secondreceiver 116 and the first transmitter 102 satisfies a threshold angle,which, in some implementations, can be at least 5 degrees. Similarly,the third transmitter 106, the third receiver 118 and the fourthreceiver 120 can be disposed in the third wellbore 112 and the fourthwellbore 124 such that an angle formed by a line connecting the thirdreceiver 118 and the third transmitter 106, and a line connecting thefourth receiver 120 and the third transmitter 106 satisfies thethreshold angle. In some implementations, the positions of thetransmitters and the receivers in the multiple wellbores can beperiodically changed, for example, as one of the wellbores is beingformed relative to the other existing wellbore, such that the angledescribed above is maintained to satisfy the threshold angle. Thesensitive volume of the sensing system can include a trapezoidal shapethat is formed by connecting the two transmitters and the two receiversin each case. To increase the coverage, more than two transmitters andmore than two receivers may be used.

FIG. 2 is a block diagram of an example of a control system 200 forranging in multiple wellbores that can implement either partialcompensation or full compensation or both. The control system 200 can beimplemented as a computer system (for example, a desktop computer, alaptop computer, a tablet computer, a personal digital assistant, asmartphone, and the like) that executes computer instructions stored ona computer-readable medium 222 to perform the operations described here.The control system 200 can be connected to a transmitter unit 202 and areceiver unit 204. Each of the transmitter unit 202 and the receiverunit 204 can be implemented as computer instructions stored on thecomputer-readable medium 222 and executable in response to instructionsfrom the control system 200. The transmitter unit 202 can be connectedto the multiple transmitters disposed in the wellbores (for example, thetransmitter 106, the transmitter 108). The receiver unit 204 can beconnected to the multiple receivers disposed in the wellbores (forexample, the receiver 118, the receiver 120).

Each transmitter can be connected to or can include a respectivetransmitting antenna (for example, a transmitting antenna 206 connectedto the transmitter 106, a transmitting antenna 208 connected to thetransmitter 108, other transmitting antennas connected to respectivetransmitters). Similarly, each receiver can be connected to or caninclude a respective receiving antenna (for example, a receiving antenna210 connected to the receiver 118, a receiving antenna 212 connected tothe receiver 120, other receiving antennas connected to respectivereceivers). In some implementations (including the partial compensationand full compensation implementations), the control system 200 can causethe one or more transmitting antennas to produce EM excitation signalsin the surrounding formations, for example, using the transmitter unit202. The control system 200 can cause the one or more receiving antennasto receive the EM excitation signals produced by the multipletransmitting antennas, for example, using the receiver unit 204. The EMsignals received by the receiving antennas are affected by properties ofthe formation in which the transmitters and the receivers are disposed.The excitation signals for the transmitting antennas can be singlefrequency or broad-band. For broad-band excitations, receivers canrecord the time domain signals and compute the associated frequencydomain signals via Fourier transform.

The control system 200, which is connected to the multiple transmittersand the multiple receivers, can receive the multiple signals, each ofwhich is a representation of each signal received by each receiver fromeach transmitter. For example, the control system 200 can receive eachsignal as a complex voltage. The control system 200 can store themultiple signals in a computer-readable storage medium (for example, thecomputer-readable medium 222). The control system 200 can implementpartial compensation or full compensation techniques (described below)on the multiple signals resulting in multiple compensated signals. Thecontrol system 200 can store the multiple compensated signals in thecomputer-readable storage medium. The control system 200 can process themultiple compensated signals to determine a position of the firstwellbore (for example, the wellbore 110) relative to the second wellbore(for example, the wellbore 122), and provide the position, for example,to a display device (not shown) connected to the control system 200.

In full compensation implementations, the control system 200 canimplement the compensation technique based on EM signals transmitted byat least two transmitters and received by at least two receivers. To doso, from the signals exchanged by the at least two transmitters and theat least two receivers, the control system 200 can determine multiplecompensated signals. The control system 200 can determine at least onecompensated signal from a first signal received from a first wellboreand a second signal received from a second wellbore. Each of thetransmitters and the receivers provides both amplitude and phasemeasurements. The control system 200 can measure a value of each EMsignal, i.e., measure an amplitude and phase of each EM signal, forexample, by digitizing the signal. In the example configurationsdescribed in FIG. 1B, the control system 200 can obtain fourmeasurements from the two transmitters disposed in the productionwellbore and the two receivers disposed in the injection wellbore—fromtransmitter 106 to receiver 118, from transmitter 106 to receiver 120,from transmitter 108 to receiver 118, and from transmitter 108 toreceiver 120. The control system 200 can receive the measurements ascomplex voltages, each having an amplitude and a phase.

From these measurements, the control system 200 can obtain an R value,which is a signal ratio. For example, at a first time instant, thecontrol system 200 can determine a first product of a value of a firstsignal transmitted by the transmitter 106 to receiver 118 (T1R1) and avalue of a second signal transmitted by transmitter 108 to receiver 120(T2R2). At the first time instant, the control system 200 can alsodetermine a second product of a value of a third signal transmitted bythe transmitter 106 to receiver 120 (T1R2) and a value of a fourthsignal transmitted by the transmitter 108 to receiver 118 (T2R1). Thecontrol system 200 can divide the first product by the second productresulting in a first compensated signal. The R value, which indicatesformation properties, changes over time for ranging applications.

A compensated signal has the capability of cancelling any multiplicativeeffects for transmitters or receivers in the form V′_(TXRY) ^(t)=C_(TX)^(t)C_(RY) ^(t)V_(TXRY) ^(t), where V′ is the voltage that is affectedby the multiplicative effect on transmitter X (C_(TX)) and V is theideal measurement with no effects. When the control system 200determines the four term ratio of the signals as described above,multiplicative effects cancel out as shown below:

${R(t)} = {\frac{V_{T\; 1\; R\; 1}^{\prime\; t}V_{T2R2}^{\prime t}}{V_{T1R2}^{\prime t}V_{T2R1}^{\prime t}} = {\frac{C_{T1}^{t}C_{R1}^{t}V_{T1R1}^{t}C_{T2}^{t}C_{R2}^{t}V_{T2R2}^{t}}{C_{T1}^{t}C_{R2}^{t}V_{T1R2}^{t}C_{T2}^{t}C_{R1}^{t}V_{T2R1}^{t}} = \frac{V_{T1R1}^{t}V_{T2R2}^{t}}{V_{T1R2}^{t}V_{T2R1}^{t}}}}$

Similarly, to operations performed at the first time instant, at asecond time instant, the control system 200 can determine a thirdproduct of a value of a fifth signal transmitted by the transmitter 106and received by the receiver 118 and a value of a sixth signaltransmitted by the transmitter 108 and received by the receiver 120. Atthe second time instant, the control system 200 can determine a fourthproduct of a value of a seventh signal transmitted by the transmitter106 and received by the receiver 120 and a value of an eighth signaltransmitted by the transmitter 108 and received by the receiver 118. Thecontrol system 200 can divide the third product by the fourth productresulting in a second compensated signal. In this manner, the controlsystem 200 can take a difference in time to obtain a time-lapsemeasurement, for example, between the first time instant and the secondtime instant.

Between the first time instant and the second time instant, the multipletransmitters and the multiple receivers can be stationary.Alternatively, either the multiple transmitters or the multiplereceivers (or both) can be moved between the first time instant and thesecond time instant. A decision to move the transmitters or receivers(or both) or keep the transmitters or receivers (or both) stationary candepend on a length of the wellbore (for example, the injection wellbore)that has been drilled between the first time instant and the second timeinstant. For example, if the multiple receivers are affixed to the MWDtool, which is moved as the wellbore is being drilled, then the multiplereceivers can move between the first time instant and the second timeinstant. If an angle (described above) formed by the multiple receiverswith a transmitter no longer satisfies the threshold after the MWD toolhas moved, then the transmitters can also be moved.

In some implementations, at the instant that the control system 200causes the transmitters to transmit the EM signals and the receivers toreceive the EM signals, the receivers and the transmitters can bestationary. Alternatively, either one or more of the transmitters or oneor more of the receivers (or both) can be mobile during EM signaltransmission and reception. In this manner, the control system 200 canreceive the multiple signals from multiple first locations of thetransmitters and the receivers, and multiple other signals from multiplesecond locations to which the multiple transmitters and the multiplereceivers are moved in the wellbores.

The control system 200 records the compensated signal as a function oftime. In general, a function ƒ can be used before the subtraction asshown below:

${R(t)} = \frac{V_{T1R1}^{\prime t}V_{T2R2}^{\prime t}}{V_{T1R2}^{\prime t}V_{T2R1}^{\prime t}}$S(t₁, t₂) = f(R(t₁)) − f(R(t₂))

In partial compensation implementations, the control system 200 canimplement the compensation technique based on EM signals exchangedbetween at least one transmitter, at least one receiver, and either atransmitter or a receiver. In implementations with two transmitters anda receiver, two measurements are possible—from transmitter 172 toreceiver 178 (T1R1) and from transmitter 179 to receiver 178 (T2R1). Inimplementations with two receivers and a transmitter, two measurementsare possible—from transmitter 152 to receiver 156 (T1R1) and fromtransmitter 152 to receiver 158 (T1R2). The control system 200 canreceive the EM signals as are complex voltages, each having a respectiveamplitude and a phase. In the example with two transmitters and onereceiver, to determine an R (ratio) value, the control system 200 candivide a value (i.e., a voltage value) of a first signal transmitted bytransmitter 172 to receiver 178 (T1R1) by a value of a second signaltransmitted by transmitter 179 to receiver 178 (T2R1). When the controlsystem 200 takes the two term ratio of the signals, multiplicativeeffects cancel out as shown below, resulting in a first compensatedsignal:

${R^{R}(t)} = {\frac{V_{T1R1}^{\prime t}}{V_{T2R1}^{\prime t}} = {\frac{C_{T1}^{t}C_{R1}^{t}V_{T1R1}^{t}}{C_{T2}^{t}C_{R1}^{t}V_{T2R1}^{t}} = \frac{C_{T1}^{t}V_{T1R1}^{t}}{C_{T2}^{t}V_{T2R1}^{t}}}}$

The control system 200 can implement the afore-described partialcompensation techniques at a first time instant. At a second timeinstant, the control system 200 can divide a value of a third signaltransmitted by transmitter 172 to receiver 178 by a value of a fourthsignal transmitted by transmitter 179 to receiver 178. The controlsystem 200 can divide the third signal by the fourth signal resulting ina second compensated signal. The R value, which indicates formationproperties, changes over time for ranging applications. Partiallycompensated signal has the capability of canceling any multiplicativeeffects for either transmitters in the following form:V′ _(TXRY) ^(t) =C _(TX) ^(t) C _(RY) ^(t) V _(TXRY) ^(t)

In the equation above, V′ is the voltage that is affected by themultiplicative effect on transmitter X (C_(TX)) and V is the idealmeasurement with no effects.

Similarly, in the example with two receivers and one transmitter, todetermine an R (ratio) value, the control system 200 can divide a firstsignal transmitted by transmitter 152 to receiver 156 (T1R1) by a valueof a second signal transmitted by transmitter 152 to receiver 158(T1R2). When the control system 200 takes the two term ratio of thesignals, multiplicative effects cancel out as shown below:

${R^{T}(t)} = {\frac{V_{T1R1}^{\prime t}}{V_{T1R2}^{\prime t}} = {\frac{C_{T1}^{t}C_{R1}^{t}V_{T1R1}^{t}}{C_{T1}^{t}C_{R2}^{t}V_{T1R2}^{t}} = \frac{C_{R1}^{t}V_{T1R1}^{t}}{C_{R2}^{t}V_{T\; 1{R2}}^{t}}}}$

The control system 200 can implement the afore-described partialcompensation techniques at a first time instant. At a second timeinstant, the control system 200 can divide a value of a third signaltransmitted by transmitter 152 to receiver 156 by a value of a fourthsignal transmitted by transmitter 152 to receiver 158. Similarly to fullcompensation, the received signal, in partial compensation, can berecorded as a function of time, and a difference in time can be taken toobtain a time-lapse measurement.S(t ₁ ,t ₂)=ƒ(R(t ₁))−ƒ(R(t ₂))

In this equation, R can be uncompensated, partially compensated or fullycompensated depending on the type of compensation technique that thecontrol system 200 implements. One example of the function ƒ is theidentity function, i.e., ƒ(x)=x. Another example for the function ƒ isthe logarithmic function, which makes S indicate the logarithmic changein the signal levels between the first time instant (i.e., t₁) and thesecond time instant (i.e., t₂). Other examples of the function ƒ arealso possible. Further, in some implementations, the control system 200can determine a second difference of measurements at three timeinstants.

In some implementations, the control system 200 can be connected to adata acquisition unit 214 to receive signals received by the controlsystem 200 from the receiver unit 204. As an alternative or in additionto storing the signals in the computer-readable medium 222, the signalscan be stored in a data buffer 216 connected to the control system 200and the data acquisition unit 214. The processor (for example, a dataprocessing apparatus 218) can be implemented as a component of thecontrol system 200 or can reside external to the control system 200 (orboth). To provide the position of the first wellbore relative to thesecond wellbore, for example, to a display device at the surface, thecontrol system 200 can be connected to a communication unit 220, whichcan transmit data using either wired or wireless networks (or both). Forexample, the communication unit 220 can be implemented as a telemetrysystem.

In the example operations described with reference to the control system200, the compensation technique is implemented as computer operations.Alternatively or in addition, the compensation technique can beimplemented using hardware or firmware. For example, the ratios used inthe compensation technique can be calculated by hardware by measuringphase difference and attenuation between the receivers instead of (or inaddition to) measuring the absolute signals. Additional time-lapseprocessing can also be applied on the compensated signal. The controlsystem 200 can be implemented down hole or at the surface.

FIG. 3 is an example of a preprocessing unit for preprocessingelectromagnetic signals before partial compensation or fullcompensation. As shown in FIG. 3 , the control system 200 can includemultiple components for preprocessing, each of which can be implementedas a computer-readable medium storing instructions executable by theprocessor (for example, the data processing apparatus 218). In someimplementations, the control system 200 can implement preprocessingtechniques on the multiple signals received from the one or moretransmitters before implementing the compensation techniques. Forexample, a first preprocessing unit 304 can receive sensor data frommultiple sources (i.e., the transmitters) at time t₁, i.e., the firsttime instant. A second preprocessing unit 302 can receive sensor datafrom multiple sources (i.e., the transmitters) at time t₂, i.e., thesecond time instant. In some implementations, a compensated signalcalculation unit 306 can implement resistivity logging signal processingtechniques, for example, multi-component synthesis, differential signalsynthesis, virtual arrays created from depth/time delayed data, orcombinations of them. The preprocessing can include filtering withrespect to time or depth to improve signal to noise ratio. Thepreprocessing can additionally include multi-array synthesis bycombining information from different sensor positions. The preprocessingcan also include azimuthal binning and multi-bin processing to obtaindipole tensor components as well known in Logging While Drillingpropagation induction resistivity well logging. Preprocessing can alsoinclude calibration operation utilizing past measurements or predictedposition (or both) of moving sensor system or environmental conditions.

Alternatively, or in addition, the control system 200 can implement aninversion unit 308 based on the compensated signal via forward modeling(for example, that uses a forward model 310) and feedback (for example,that uses a library 312). The inversion units accept the compensatedsignals as the input and outputs pipe or environmental parameters suchas pipe distance and direction, transmitter location, receiver location,environmental parameters, and the like. Based on the difference betweeninput signals and the modeling result, variable set of output parameterscan be adjusted to reduce the difference. The afore-described operationscan be iterated and stopped once the difference reduces and satisfies athreshold. Alternatively, or in addition, a look-up table that maps theinput to output parameters can be computed and used. Parametersincluding pipe distance and direction, transmitter location, wellboresize, and other environmental parameters can be obtained by implementingpreprocessing.

FIGS. 4A and 4B are plots comparing compensated and uncompensatedelectromagnetic signals. The electromagnetic signals received by thereceivers are used to determine the distance between the two wellboresin which the transmitters and the receivers are disposed. In the case ofno time-lapse signal measurement, a high signal can indicate that thewells are close and a low signal can indicate that the wells are farapart. In the case of time-lapse signal measurement, a high signal canindicate that the wells are getting closer and a low signal can indicatethat the separation between the wells is increasing. The inversionprocess described above can be the basis on which the interpretation ofcloseness from the compensated signals is made. The plots shown in FIGS.4A and 4B are determined by ranging in the SAGD application. Plot 402 isa plot of time-lapsed attenuation versus time for measured compensatedsignals, true compensated signals, measured uncompensated signals, andtrue uncompensated signals. Plot 404 is a plot of time-lapse phaseversus time for measured compensated signals, true compensated signals,measured uncompensated signals, and true uncompensated signals. Theproduced signal is used to determine the position of the receivers orequivalently the tool body with respect to a reference such as alocation in the injector or producer wells, or a previously knownposition of the receiver. Although the receiver is moving in thisexample, the transmitter could alternatively or in addition be moving.In this example, an amplitude drift and phase draft is used on all ofthe receivers. The plots show that, despite the draft, the compensatedmeasurement is not affected from phase shifts whereas uncompensatedmeasurements are affected.

FIG. 5 is a flowchart of an example process 500 for ranging frommultiple wellbores implementing full compensation. The process 500 canbe implemented as computer instructions stored on computer-readablemedia (for example, the computer-readable medium 222) and executable bythe processor (for example, data processing apparatus 218). For example,the process 500 can be implemented by the control system 200. At 502,multiple signals are received. Each signal corresponds to anelectromagnetic signal received by a receiver of multiple receiversdisposed in multiple wellbores from a transmitter of multipletransmitters disposed in the multiple wellbores.

At 504, full compensation techniques are implemented on the multiplesignals resulting in multiple compensated signals. For example, from thereceived multiple signals, multiple compensated signals can bedetermined. At least one compensated signal can be determined from afirst signal received from a first wellbore and a second signal receivedfrom a second wellbore of the plurality of wellbores. At 506, themultiple compensated signals are processed to determine a position of afirst wellbore of the multiple wellbores relative to a second wellboreof the multiple wellbores. At 508, the position of the first wellborerelative to the second wellbore is provided.

FIG. 6 is a flowchart of an example process 600 for ranging frommultiple wellbores implementing partial compensation. The process 600can be implemented as computer instructions stored on computer-readablemedia (for example, the computer-readable medium 222) and executable bythe processor (for example, the data processing apparatus 218). Forexample, the process 500 can be implemented by the control system 200.At 602, multiple signals are received. Each signal corresponds to anelectromagnetic signal exchanged by a first transmitter disposed in afirst wellbore to transmit electromagnetic signals, a first receiverdisposed in a second wellbore to receive the electromagnetic signalstransmitted by the first transmitter, and either a second transmitter ora second receiver. The second transmitter or the second receiver can bedisposed in either the first wellbore or in the second wellbore or in alocation other than the wellbore (for example, at the surface).

At 604, partial compensation techniques are implemented on the multiplesignals resulting in multiple compensated signals. At 606, the multiplecompensated signals are processed to determine a position of a firstwellbore of the multiple wellbores relative to a second wellbore of themultiple wellbores. At 608, the position of the first wellbore relativeto the second wellbore is provided.

A number of embodiments have been described. Nevertheless, it will beunderstood that various modifications may be made without departing fromthe spirit and scope of the invention.

What is claimed is:
 1. A system for ranging in wellbores, the systemcomprising: a first transmitter, disposed in a first wellbore of aplurality of wellbores, and configured to transmit electromagneticsignals; a first receiver, disposed in a second wellbore of theplurality of wellbores, and configured to receive the electromagneticsignals transmitted by the first transmitter; either a secondtransmitter or a second receiver disposed in either the first wellboreor the second wellbore to communicate the electromagnetic signals withthe first transmitter or the first receiver; and a processor connectedto the first transmitter, the first receiver, and either the secondtransmitter or the second receiver, the processor configured to: receivea plurality of signals communicated by the first transmitter, the firstreceiver, and either the second transmitter or the second receiver,wherein the plurality of signals includes a signal that corresponds toan electromagnetic signal received by the first receiver from the firsttransmitter; implement compensation techniques on the plurality ofsignals resulting in a plurality of compensated signals; process theplurality of compensated signals to determine a position of the firstwellbore of the plurality of wellbores relative to the second wellboreof the plurality of wellbores; provide the position of the firstwellbore relative to the second wellbore; and control the position ofthe first wellbore relative to the second wellbore based on the providedposition.
 2. The system of claim 1, comprising the second transmitter,disposed in the first wellbore of the plurality of wellbores, andconfigured to transmit the electromagnetic signals, wherein the firstreceiver is disposed in the second wellbore to receive theelectromagnetic signals transmitted by the second transmitter, andwherein the processor is further configured to receive an additionalsignal that corresponds to an additional electromagnetic signal receivedby the first receiver from the second transmitter.
 3. The system ofclaim 2, wherein the processor is further configured, at a first timeinstant, to divide a value of a first signal transmitted by the firsttransmitter and received by the first receiver, by a value of a secondsignal transmitted by the second transmitter and received by the firstreceiver, resulting in a first compensated signal.
 4. The system ofclaim 3, wherein the processor is further configured, at a second timeinstant, to divide a value of a third signal transmitted by the firsttransmitter and received by the first receiver, by a value of a fourthsignal transmitted by the second transmitter and received by the firstreceiver, resulting in a second compensated signal.
 5. The system ofclaim 4, wherein the processor is further configured to: record thefirst compensated signal and the second compensated signal as a firstfunction of time and a second function of time, respectively; and obtaina time-lapse measurement between the first time instant and the secondtime instant.
 6. The system of claim 5, wherein, to obtain thetime-lapse measurement, the processor is configured to: apply alogarithmic function to the first function of time; apply a logarithmicfunction to the second function of time; and determine a differencebetween the logarithmic function applied to the first function of timeand the logarithmic function applied to the second function of time. 7.The system of claim 1, comprising the second receiver, disposed in thesecond wellbore of the plurality of wellbores, and configured to receivethe electromagnetic signals transmitted by the first transmitter, andwherein the processor is further configured to receive an additionalsignal that corresponds to an additional electromagnetic signal receivedby the second receiver from the first transmitter.
 8. The system ofclaim 7, wherein the processor is further configured to divide a valueof a third signal transmitted by the first transmitter and received bythe first receiver, by a value of a fourth signal transmitted by thefirst transmitter and received by the second receiver, resulting in asecond compensated signal.
 9. The system of claim 7, wherein the firstwellbore is a steam-assisted gravity drainage (SAGD) wellbore beingdrilled, and wherein either the first receiver or the first transmitteror the second receiver or the second transmitter is disposed in the SAGDwellbore.
 10. The system of claim 9, wherein the second wellbore is apre-existing production wellbore, and wherein either the first receiveror the first transmitter or the second receiver or the secondtransmitter is disposed in the pre-existing production wellbore.
 11. Thesystem of claim 9, further comprising a measurement while drilling (MWD)tool in the SAGD wellbore, wherein a combination including at least twoof the first receiver, the first transmitter, the second receiver, orthe second transmitter are affixed to and spaced apart on the MWD tool.12. The system of claim 7, wherein the processor is further configuredto measure a value of each of the plurality of signals as a complexvoltage.
 13. The system of claim 7, wherein the processor is configuredto: receive the plurality of signals received by the first receiver andthe second receiver disposed at a first location and a second location,respectively, within the second wellbore from the first transmitterdisposed at a third location within the first wellbore; and receiveanother plurality of signals received by the first receiver and thesecond receiver moved to a fourth location and a fifth location,respectively, within the second wellbore from the first transmitterdisposed at the third location.
 14. The system of claim 1, furthercomprising a non-transitory computer-readable storage medium to storethe plurality of signals and the plurality of compensated signals.
 15. Anon-transitory computer-readable medium storing instructions executableby a processor to perform operations for ranging in wellbores, theoperations comprising: receiving a plurality of signals communicatedbetween a first transmitter, disposed in a first wellbore of a pluralityof wellbores, and configured to transmit electromagnetic signals, afirst receiver, disposed in a second wellbore of the plurality ofwellbores, and configured to receive the electromagnetic signalstransmitted by the first transmitter, and either a second transmitter ora second receiver, disposed in either the first wellbore or the secondwellbore, and configured to communicate the electromagnetic signals withthe first transmitter or the first receiver, wherein the plurality ofsignals includes a signal that corresponds to an electromagnetic signalreceived by the first receiver from the first transmitter; implementingcompensation techniques on the plurality of signals resulting in aplurality of compensated signals; processing the plurality ofcompensated signals to determine a position of the first wellbore of theplurality of wellbores relative to the second wellbore of the pluralityof wellbores; providing the position of the first wellbore relative tothe second wellbore; and controlling the position of the first wellborerelative to the second wellbore based on the provided position.
 16. Amethod for ranging in wellbores, the method comprising: receiving, by aprocessor, a plurality of signals communicated between a firsttransmitter, disposed in a first wellbore of a plurality of wellbores,and configured to transmit electromagnetic signals, a first receiver,disposed in a second wellbore of the plurality of wellbores, andconfigured to receive the electromagnetic signals transmitted by thefirst transmitter, and either a second transmitter or a second receiver,disposed in either the first wellbore or the second wellbore, andconfigured to communicate the electromagnetic signals with the firsttransmitter and the first receiver, wherein the plurality of signalsincludes a signal that corresponds to an electromagnetic signal receivedby the first receiver from the first transmitter; implementing, by theprocessor, compensation techniques on the plurality of signals resultingin a plurality of compensated signals; processing, by the processor, theplurality of compensated signals to determine a position of the firstwellbore of the plurality of wellbores relative to the second wellboreof the plurality of wellbores; providing, by the processor, the positionof the first wellbore relative to the second; and controlling theposition of the first wellbore relative to the second wellbore based onthe provided position.